Filed by 3TEC Energy Corporation
                                       Pursuant to Rule 425 of the Securities
                                       Act of 1933 and deemed filed pursuant to
                                       Rule 14a-12 of the Securities Exchange
                                       Act of 1934 Subject Company: 3TEC Energy
                                       Corporation Commission File No:
                                       001-14745

The following is the transcript of a conference call made by Plains Exploration
& Production Company:


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                              PLAINS EXPLORATION FOURTH QUARTER EARNINGS RESULTS
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                                    PLAINSXP
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                                February 20, 2003
                                   11:00 am CT

Jim Flores:   Good morning everyone I hope we are on line. We had some
              technical difficulties with our long distance provider. That seems
              to be the tale of the tape with Telecom these days. Welcome to the
              Plains Exploration Production Company 2002 Fourth Quarter and
              Annual results conference call.

              Joining us this morning is John Raymond our President and Chief
              Operating Officer, Steve Thorington our Executive Vice President
              and Chief Financial Officer, Tim Stephens, Executive Vice
              President General Counsel and Tom Gladney our Senior Vice
              President of Operations.

              John will be reviewing our year-end result picture and provide
              operational update. Steve will then discuss our 2002 financial
              results and 2003 guidance and then of course open it up for
              questions. Let me first take care of some of the obligatory legal
              housekeeping items. We have continually operated under the legal
              safe harbor statement.

              This conference call may contain statements that are considered
              forward-looking statements as defined by the SEC. Such statements
              include but may not be limited to PXPs merger and strategic plans,
              corporate expectations, objectives for future operations.




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              I refer you to PXP's forward-looking statement contained at the
              bottom of the press release issued this morning. I will also refer
              you to PXPs forward-looking statements contained in SEC filings
              and hereby incorporate those by reference. We also recommend that
              investors read the registration statement on Form S-4 filed with
              the SEC in connection with the proposed merger with 3TEC Energy
              Corporation and a safe harbor statements included therein.

              There with all of the housekeeping out of the way let me get back
              to the business at hand with PXP and the 2002 results. We were
              highly successful and it was a pivotal year for Plains Exploration
              Production Company. The highlights include the completion of the
              tax free spin from Plains resources which was a heroic event for
              all involved from the standpoint of management continued to put up
              good operating results.

              Our operating people our financial people did double time and I
              want to thank everybody involved with that process and was very
              successful meeting all of the IRS requirements to successfully
              separate those two businesses. And now with the separate platforms
              you can see how fast we can start growing the business with the
              acquisition of 3TEC on the PXP side.

              Directly related to PXP and the operations we had record
              production and reserve volumes. John Raymond will discuss that in
              detail. We also doubled our interest in our Point Arguello unit,
              which has become a significant production enhancement for the
              company. And then our forward-looking growth will include the
              initiation of the first 3-D seismic program in the Los Angeles
              basin at our Inglewood field that John will also discuss in
              detail about how that is going.

              And then of course we announced on February 3 that we entered into
              an agreement to acquire 3TEC Energy. The transaction will
              significantly grow



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              and diversify our reserve base. That was very accretive to our
              existing shareholders and on the advice of counsel since we are in
              a quiet period we want to limit all of the remarks and questions
              today to PXP standalone. With that I would like to turn over the
              call to John for the operating results.

John Raymond: Thanks Jim, good morning and welcome as always we appreciate your
              time and interest. Over the course of the next 20 minutes I am
              going to discuss 2002 year end reserves review our fourth quarter
              operational performance and comment on our 2003 capital program
              and key projects.

              At this juncture everyone should have a copy of the press release
              issued this morning as well as the 8-K guidance that was filed
              with the SEC earlier this morning as well. Turning to reserves.
              PXPs crude oil and gas reserves increased approximately 6% during
              2002 to a total of 253 million barrels of oil equivalent at
              December 31, 2002. Reserve additions were 23 million barrels
              equivalent resulting in a 247% reserve replacement ratio at an all
              in cost of $2.80 per BOE.

              Reserve additions include 16.2 million barrels equivalent for
              field extensions and improved recovery and 2.6 million barrels
              equivalent related to property acquisitions namely the additional
              interest at Point A that we acquired from Phillips in August of
              2002.

              At year-end of 2002 the pre tax net present value of proved
              reserves discounted at 10% was $1.5 billion. This compares to the
              company's reported 239.3 million barrels of oil equivalent with
              the pretax net present value again discounted at 10% of $643.2
              million at year-end 2001.

              Of course we like everyone else were affected by year-end pricing
              which was $31.20 cents per barrel and $4.79 per mmbtu for oil and
              gas respectively. To




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              address the inevitable question up front had prices been in the
              more normalized range defined as the mid 20s there would be
              roughly 10 to 20 fewer million BOEs at year end than you see in
              the 253 million BOE number.

              When viewed in the context of our objectives though we have
              consistently articulated results even on a price normalized basis
              are pretty much what we had anticipated as our goal in the near
              term is not to find more oil given our 27 year reserve life but
              rather to generate more cash flow from the existing reserve base.
              In essence shorten our reserve life using our durable underlying
              asset base.

              Turning to operations we reported record quarterly volumes as well
              as we produced approximately 2.5 million barrels of oil equivalent
              in the fourth quarter of 2002 an increase of 8% over the fourth
              quarter of 2001. The increase is primarily due to volumes
              attributable to the additional interest acquired in the Point A
              unit. Our share of production from Point A during the fourth
              quarter of `02 were 6,600 barrels a day a 51% increase compared to
              the same quarter last year due to the acquired interest.

              Our on shore California volumes are at 16,400 BOEs per day up
              slightly from the 2001 fourth quarter level. Production from our
              Illinois properties is approximately 2,500 barrels per day
              compared to 2,800 barrels per day in the fourth quarter of 2001.
              Additionally the company reported record annual volumes as
              production increased 6% to 9.3 million barrels of oil equivalent
              from previous year levels.

              In 2002 the company drilled 87 wells with a 99% success rate. The
              only failure being a well drilled early in 2002 at Point A
              targeting a higher risk location across a fault in the main field
              pipe. We anticipate drawing 187 wells in 2003, 100 more than
              drilled in 2002 with the bulk of these 100 at Mount



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              Poso which are shallow and inexpensive roughly $100,000 a piece
              and reach payout very quickly given the confluence of low service
              cost and high prices.

              To date we have drilled 28 wells all successful with 24 wells
              drilled at Mount Poso and four shallow wells at Inglewood.
              Inglewood represents approximately 30% of our reserves and is a
              business unit that consistently drills 20 to 30 wells per year. We
              have previously spoken about our drilling efficiency and continue
              to see progress as injection wells for example are now being
              drilled in three days at $65 per foot as compared to 2002 when
              wells took four days and cost $75 to $80 per foot and 2001 when
              wells took seven days and cost $80 to $85 per foot.

              Now we clearly expect (unintelligible) trend when we think about
              this in the context of total feet drilled per annum which
              approaches 60 to 75,000 feet and a five year look based upon a
              plan of 450,000 feet a little improvement you can see start to
              have a very large impact in terms of total dollars spent. The 2003
              capital program for 2003 we have a capital budget of $75 million.
              This compares to capital expenditures of $64.5 million in 2002 and
              $125.8 million in 2001.

              To be clear on 2002 spending the $64.5 million of cap ex in `02
              has been reduced by $5 million received in connection with the
              Point Arguello acquisition. Without that credit we spent $70
              million in 2002. Included in the 2003 budget is an estimated $8.7
              million of capitalized G&A and a couple million dollars of
              capitalized interest so our direct and drilling and maintenance
              cap ex is expected to be on the order of $64 million.

              Remember also that as we discussed as couple of weeks ago in the
              3TEC acquisition conference call that final spending this year
              will be a function of



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              high grade and combined companies opportunity set in allocating
              capital accordingly.

              Now I want to update you on a few of the more impactful projects
              we have scheduled for this year. Inglewood deep - recall that
              this project encompasses the redevelopment of the deep sands of
              Inglewood. Deep defined at 3500 to 10,500 feet via the
              application of the modern technology principally 3-D seismic that
              heretofore has note been applied on shore in the LA basin. Which I
              might add has only produced a meager 10 billion barrels since
              inception in the early 1900s.

              While the timeline has been somewhat fluid we are awaiting only
              the seismic providers air quality permits for the operations of
              their size equipment. All other aspects of the shoot are fully
              permitted at this point. We expect shooting to begin within the
              first two weeks of March.

              At Rocky Point we expect to file responses to technical review
              questions to an application in conjunction with the necessary
              partner agreements shortly. At that point it falls into the hands
              of the various regulatory bodies and will advance from there. At
              what pace I will not attempt to predict. All I will say is that we
              continue to believe it to be a solid project with good merit given
              the development of existing reserves from existing infrastructure.

              To that end we hope the various regulatory bodies agree and we
              will respectfully await their formal response. In conclusion when
              I think about the accomplishment of 2002 as Jim alluded to they
              clearly set the stage for the future.

              We have a very solid reserve base and the strength with which
              provides us with a unique platform in the form of a solid
              foundation upon which to build



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              both organically -- Inglewood deep and Rocky Point for example
              -- as well as via the pursuit of outside opportunities such as the
              recently announced 3TEC transaction that will upon consummation
              significantly enhance the geographic and functional diversity and
              financial flexibility of our business.

              The one characteristic of this business that is, has been and will
              continue to be a certainty is uncertainty. This is not a dynamic
              that we feared. To the contrary we find it that uncertainty is our
              best friend because it brings with it opportunity. The greater the
              uncertainty of times the greater the opportunity set. And I can
              assure you that there are many people around here who have spent
              many nights trying to convert uncertainty into manageable risks.
              Thereby identifying quality opportunities.

              There is risk in winning the game is having the platforms in place
              to capture the opportunity when we manifest it. Prior to 3TEC in
              my judgment we had a good platform. Post 3TEC we will have a great
              platform for growth and accordingly we are moving as fast as
              practicable to close the transaction and reload our pistol for
              future opportunities. Having said that I will turn the call over
              to Steve Thorington our CFO to walk through a financial review.

Steve Thorington: Thank you John and good morning. For the fourth
                  quarter PXP reported net income of $4.7 million or 20 cents
                  per share compared with net income of $7.6 million or 31 cents
                  per share for the fourth quarter of 2001. Net income for the
                  fourth quarter was impacted by $5.1 million of pretax charges
                  related to the company's separation from Plains Resources. And
                  that includes $3.7 million which is the in the money value of
                  stock appreciation rights issued at the spend dates.

              As you probably know we use SARs at PXP instead of employee stock
              options. Recurring that income meaning the net of the impact of
              these special



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              charges waiting for separation from PLX was $7.1 million or 33
              cents per share. Unit gross margin increased to $12.07 per barrel
              equivalent the fourth quarter of 2002 compared to $11.74 per
              barrel equivalent in the comparable period of 2001 due to higher
              realized prices.

              The company's average realized oil price, which is net of quality
              and location differentials and the impact of hedges was $20.63 per
              barrel as compared to $18.93 per barrel in the fourth quarter of
              last year. Our average crude oil differential was $4.41 per
              barrel, which was approximately 20 cents below the 2001 fourth
              quarter differential.

              Unit production expenses were $8.70 per BOE compared to $6.85 in
              the fourth quarter of 2001. Approximately a $1.00 of this increase
              is attributable to the Point Arguello unit, which has a higher
              unit cost than most of our other properties. And as John said we
              doubled our interest of July of 2002. In addition fourth quarter
              2001 production expense of Point Arguello benefited by credits as
              results of successful property tax appeal.

              Per unit expenses for Point Arguello are increasing though as
              production declines due to the large component of fixed expenses
              for this property. Excluding Point A production expenses increased
              by 85 cents per BOE from the fourth quarter 2001 level. This
              increase is primarily attributable to the increase electricity
              prices in California higher work over and maintenance expense as
              well as increase in insurance cost that the entire industry is
              suffering from.

              Turning to annual results for the full year the company reported
              net income of $26.2 million or $1.08 per share compared to net
              income of $53.2 million or $2.20 per share in 2001. The full year
              pretax impact though of the special charges related to the
              separation from Plains Resources this year was



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              approximately $6.8 million. Unit gross margin was $11.76 per
              barrel equivalent in 2002 as compared to $15.93 per barrel
              equivalent in the comparable period of 2001, which benefited
              substantially from higher gas prices than we had in 2002.

              For example PXP received an average of $8.58 per mcf for its gas
              production in 2001 compared to $3.06 in 2002. Unit production
              expenses for 2002 were $8.40 BOE compared to $7.27 in 2001. This
              increase is primarily attributable to increased electricity cost
              in California higher work over maintenance expense as well as
              increased insurance cost.

              G&A expenses of $1.68 per BOE in the fourth quarter of this year
              included the special spin costs I have already talked about.
              Excluding those G&A costs we had G&A of $1.15 per BOE for the full
              year. But that figure is actually low and it is not really
              representative of what we expect the company to have going forward
              because it involved some certain special allocations from PLX. And
              we will talk about that in more detail when I get to the guidance.

              As to capital structure and our hedge position at year-end we had
              outstanding consolidated debt of $233.7 million, which includes
              $35.8 million that was outstanding under a revolving credit
              facility at that time. Our year-end balance sheet reflects the
              working capital deficit of $49 million. Approximately $22 million
              of this amount is FAS 133 related and is attributable to the fair
              value of our crude oil hedges. And $9 million is attributable to
              the semi-annual interest payment on our sub notes, which we
              subsequently paid on January 2, 2003.

              Turning back to FAS 133, as you know accounting rules require that
              we record the fair value of hedge instruments on our balance
              sheet. But they do not allow us to record the offsetting amounts
              leaning towards our physical



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              production. Hedges are recorded on our balance sheet based on
              crude oil prices at quarter end.

              If the physical barrels hedged were recorded at fair value as well
              the mark to market losses for the hedge instruments reflected in
              our balance sheet would be offset by an increase in the value of
              the physical barrels. We have locked in a fixed price for a
              portion of our production and reduced our exposure to price
              volatility. However due to accounting rules our balance sheet is
              not reflective of the entire transaction.

              We continue to be committed to hedging. Our 2003 hedge position
              consists of 19,250 barrels per day of swaps at an average price of
              $22.81. For 2004 we have hedged 17,500 barrels per day with swaps
              at an average price of $23.82. And for 2005 we have hedged 5,000
              barrels per day with swaps at an average price of $23.57 per
              barrel.

              Now I will turn to guidance and as you know we did also file with
              the SEC this morning an 8-K that includes this guidance.
              Production volumes for 2003 are expected to range between 9.4 and
              9.6 million barrels of oil equivalent consisting of 95% oil and 5%
              gas. Production expenses are estimated at $9.15 per BOE.

              Estimated production expenses for 2003 are higher than the 2002
              level because they will include a fill year impact of a doubling
              of the Point Arguello interest as well as a full year of increased
              electric and insurance costs. We estimate that our oil
              differential to NYMEX will average around $4.50 per barrel during
              2003.

              We are reminded that we are locked in the NYMEX differential on
              approximately 70% of our estimated 2003 productions. Our unit G&A
              costs



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              are expected to average $1.50 to $1.60 per BOE in 2003. This
              amount excludes any expense related to stock appreciation rights
              which are subject to variable accounting rules. As a result our
              reported results of operations will be affected by fluctuations of
              the price of our common stock.

              At the end of each quarter we will compare the per share price of
              our common stock to the exercise price of each outstanding or
              unexercised stock appreciation rights but is vested or for
              accounting purposes is deemed vested at the end of that period.
              Let me be clear about the concept of "deemed vested".

              And an example if a SAR is scheduled to vest on December 31 for
              accounting purposes one fourth of the shares are deemed of that at
              the end of each quarter. Even though no vesting occurs actually
              until December 31. To the extent the closing price at the end of
              each period exceeds the exercise price we will recognize the
              access as an accounting charge to the extent not previously
              recognized.

              If the quarter ending closing price declines compared to prior
              periods we will recognizes credits to income to the extent we have
              previously recognized expense. We have approximately 4 million
              SARs outstanding with an average exercise price of $8.70. At
              December 31 2002 1.7 million of SARs were deemed vested.

              We realize that for most of you SARs are probably a new concept
              and we will do our best going forward to provide you with enough
              information in our financial reports then you can fully understand
              their impact. Remember that these came about in connection with
              splitting the employees stock options that were outstanding in
              Plains Resources before the spin-off. While we will have



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              a cash disperse when the SARs are exercised there will be no
              change to our share count as happens with stock options.

              In fact we have no outstanding options or warrants. Based on the
              book value of the company's crude oil and gas properties at
              December 31, 2002 and reserve volumes and future development costs
              included in the reserve reports at that date the 2003 DD&A rates
              for oil and gas properties will be approximately $3.53 per BOE.
              That number will be revised when we complete the calculations to
              implement FAS 143 effective January 1 of 2003.

              Under FAS 143 we will record a liability equal to our discounted
              estimated abandonment cost and a corresponding increase to oil and
              gas properties. We don't expect that expense recognized after FAS
              143 to exceed the 3.53 for BOE estimates although a portion of the
              expense would be recognized as accretion expense rather than DD&A
              expense.

              Finally we estimate that our tax rate for 2003 will be 41% with a
              5% current rate. The 2003 current rate is lower than the rate
              reflected in our 2002 financial statements because that rate was
              based on the tax allocation agreement with Plains Resources Inc.
              prior to the spin-off. With that I will turn the call back to Jim.

Jim Flores:   Thanks Steve and we will open it up at this point in time for
              questions.

Conference Coordinator: Thank you. If you would like to ask a question please
                        press the star key followed by the 1 on your touchtone
                        telephone. To withdraw your question in the queue press
                        pound. Once again if you would like to ask a question
                        press star 1. We will take our first question from the
                        site of Drew Victor of Tiedemann Funds.



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Drew Victor:  Okay well I guess I didn't expect to be first but I just
              had a question really on you had mentioned the S-4 came out and
              you had a condition in there that you needed an IRS ruling. And I
              wasn't sure that was something you were going to say how long that
              would take. And what the status of that was.

Steve Thorington: Drew it is condition clause that we have an IRS ruling to make
                  sure it doesn't have a negative effect on the tax free spin.
                  But I will turn it over to Tim Stephens our General Counsel to
                  discuss this further. I don't know if we can talk about it.

Tim Stephens: Drew there is not - a condition is not to closing. The comment I
              believe in the merger agreement related to either a tax opinion or
              in the alternative an IRS supplemental ruling.

Drew Victor:  Okay so you weren't going to go for an IRS ruling. You are
              going to rely upon the legal opinion?

Tim Stephens: Well we have a commitment on a tax opinion and I would expect that
              that is what we would close on.

Steve Thorington: And Drew this would be the normal course of business for any
                  transaction that we do for a while to make sure that we
                  honor the tax free spin to both sets of shareholders.

John Raymond: I think I would preface this whole thing that this is not new
              news. This is something that we understood going into the
              transaction and we have spent a lot of time with tax counsel and
              received their advice to given the constructs in the way that the
              transaction is contemplated at this point that a tax opinion at
              closing while it is an issue it shouldn't be an insurmountable
              issue.



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Drew Victor:  Okay can I just ask when do you think this will close?

John Raymond: Well I think what we said publicly and given the timing on the
              filing of the S-4 is sometime late May early June at the latest.
              And maybe expedited by a month depending on what happens with the
              various regulatory authorities in Washington, which we can't
              control.

Drew Victor:  Okay thanks.

Conference Coordinator:    Your next question comes from the site of
                           Larry Busnardo with Petrie Parkman.

Larry Busnardo:  Good morning.

John Raymond:    Good morning Larry.

Larry Busnardo:  John could you go back  through the numbers  that you gave out
                 on the  reserves.  Just the  year-end  pricing and the barrel
                 - I don't think I got those.

John Raymond: Sure well year-end 2002 we had 253 million BOEs. Okay now the SEC
              mandates year-end pricing flat while you know the rules as well as
              I do. And as a result you will require - we will require of you
              $31.20 a barrel for oil and $4.79 of mmbtu for gas which if I
              remember right translates into a (unintelligible) border index of
              about $4.40. Okay so that translates into the PV-10 of about $1.5
              billion at year-end 2002.

              Now the other commentary in there was basically designed to
              address upfront the issue kind of - this is interesting but how
              relevant is an issue that prices are $31.20 in the price deck were
              93% oil at that point in time. So the gas price is interesting but
              I am not sure how much of an impact it really has on us. You



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              know if you were to try to run a more normalized price deck what
              would the impact be on reserves?

              I think in prior years -- just to be clear on this point -- in
              prior years I think people spent a lot of money around here doing
              pro forma's as if prices were certain number etc. We actually
              elected not to spend the money doing that.

              But I think we have enough knowledge of our reserve base so that
              we can handicap it that if prices are in the mid 20s which is
              pretty much consistent with where our hedging program is in effect
              these days reserves will probably be somewhere between 10 and 12
              million barrels less than the 253 that we had on the books at year
              end which is a function of the off scale high price.

Larry Busnardo:  Okay and then you said extension 16.2 and acquisitions of 2.6?

John Raymond:    Precisely.

Larry Busnardo:  Okay got it Steve could you comment just a little bit on the
                 DD&A rate in the fourth quarter. It was a little bit higher
                 than I was expecting.

Steve Thorington: That is pretty much where we were assuming be coming
                  out Larry.

Larry Busnardo:   Okay.

Steve Thorington: And that is how the reserves came out.

Larry Busnardo: Okay and then just the last thing on Inglewood deep I
                know you are in the process of beginning the shoot. What will be
                the timing of that both in terms of interpretation and then
                beginning a drilling program there?



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John Raymond: Yes it probably takes call it four to six weeks to shoot it and
              then obviously as you go through the processing and interpretation
              data will trickle out slowly frankly this is an area where we will
              spend probably years specifically defining everything that we
              learn from the 3D shoot.

              Now having said that we will learn a lot of things early on really
              defined as - call it two or three months after we are done
              shooting and would anticipate drilling sometime hopefully in the
              early part of the fourth quarter at least one well if not a
              couple. As you know this is an area where drilling isn't really
              the most complex part of the operation. To the contrary it is
              pretty straightforward stuff.

              So to the extent that we get a good accurate picture out of the 3D
              in those deep sands we can put rigs -- plural -- to work pretty
              quickly.

Larry Busnardo: And in any event it probably wouldn't have any impact on
                your production this year. It would be more of a factor in `04.

John Raymond: Yes you know if we start drilling early Q4 these wells typically
              take 30 to 45 days to drill them complete. And as you know all of
              the infrastructure is already in place. So you drill them and you
              complete them and you basically turned on to that infrastructure
              that is already on the surface.

              You know there are some wells that if you look through historical
              results here that have produced on the order of 500 to 1,000
              barrels a day. So to the extent that we can really correlate with
              the 3D what was going on down there to generate those types of
              production rates we are going to put some wells down pretty
              quickly to try to capture the same results.

Larry Busnardo: Okay thanks.



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Conference Coordinator: Your next question comes from Greg Anderson with
                        Bank One.

Greg Anderson:  Hey guys.

John Raymond: Good morning Greg.

Greg Anderson: A couple of quick questions. The first question sounds like as
               you said you are drilling a lot more at Mount Poso this year
               because a little quicker reserve life and lower cost wells. Is
               that all attributable to the quality differential of the oil? Or
               are they just easier wells to drill? Can you give a little bit
               more color on that one?

John Raymond: Yes they are very shallow. They are kind of 1,500 to a couple
              thousand-foot wells. They cost about - I would say roughly
              $100,000. I think the number is about $105,000 is what they are
              running right now to drill them. Obviously with where the
              commodity price is the IP is at a pretty good rate and then have a
              decline from there. And actually I think they produce for quite a
              long time.

              They produce for a solid 10 to 15 to 20 years type of number. What
              you really want to do is capture the front end of the production
              curve. They obviously - the high percent of the reserves come off
              in the first year. So given where service costs are a couple
              (unintelligible) commodity prices are there are some pretty
              amazing returns that can be generated doing it.

              And as you can tell again in my commentary I said that today we
              drilled 28 wells and 24 of them have been at Poso. So we are a
              month and a half into the year and we basically drilled a quarter
              of the wells at Mount Poso.



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                              PLAINS EXPLORATION FOURTH QUARTER EARNINGS RESULTS
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                                                                         Page 18


Greg Anderson: Great and then the last question I had is I missed - I
               guess for Steve I missed some of the hedge numbers that he gave.
               I wondered if he could run through those again.

Steve Thorington: Yes be happy to Greg. For 2003 we have 19,250 barrels
                  per day which are hedged at an average price - if I can get
                  here again of $23.81. For 2004 we have 17,500 barrels per day
                  swapped with an average swap price of $23.82. And for 2005 the
                  volume is 5,000 barrels per day with an average price of
                  $22.57 per barrel.

Greg Anderson:  Terrific thanks.

Conference Coordinator: Once gain if you would like to ask a question please
                        press star 1 now on your touchtone phone. We will
                        take our next question from Steve Schweitzer Shenkman
                        Capital.

Steve Schweitzer: Hi good morning - just applying some of the guidance that you
                  provided in your 8-K. It seems to get me to an EBITDA number
                  of about $27 million is that pretty safe?

Steve Thorington: For which period?

Steve Schweitzer: For first quarter of 2003.

John Raymond: We specifically provide enough guidance to give you the dynamics
              that we control. I don't know what you are using for a price deck
              in there. And then the differential if you move around a little
              bit.

              So we have never gone as far as really defining it down to the
              true EBITDA number because that is a function of some constructs
              that we don't control.



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                              PLAINS EXPLORATION FOURTH QUARTER EARNINGS RESULTS
                                                           Moderator: Jim Flores
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                                                                         Page 19



              But I think if you use - again I don't know what price deck you
              are using to get to that number.

Steve Thorington: There is probably enough data in the guidance to come up with
                  your own number.

Steve Schweitzer: Okay and then have you finalized any additional plans for the
                  3TEC acquisition in terms of financing - in terms of debt
                  or have you made any progress with the banks with respect to a
                  new credit facility?

Steve Thorington: As we said early on we are not here to talk about the 3TEC
                  transaction. This is more the PXP results and guidance. Other
                  than globally everything is going as expected? There are no
                  surprises.

Steve Schweitzer:  Okay so what you outlined on your last call is still holding?

Steve Thorington:  Yes

Steve Schweitzer:  Okay thank you.

Conference Coordinator:  Once again if you would like to ask a question please
                         press star 1. There are no further questions at this
                         time. I would like to turn the call back over to
                         Mr. Flores for any additional or closing remarks.

Jim Flores:  Thank you operator we appreciate everybody's interest and see you
             at the end of next quarter.

Conference Coordinator:  This concludes today's conference. Thank you for your
                         participation. You may now disconnect.


                                      END



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                              PLAINS EXPLORATION FOURTH QUARTER EARNINGS RESULTS
                                                           Moderator: Jim Flores
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                                                                         Page 20


These statements are based on certain assumptions made by the companies based on
their experience and perception of historical trends, current conditions,
expected future developments and other factors they believe are appropriate in
the circumstances. Such statements are subject to a number of assumptions, risks
and uncertainties, many of which are beyond the companies' control. Statements
regarding future production are subject to all of the risks and uncertainties
normally incident to the exploration for and development and production of oil
and gas. These risks include, but are not limited to, inflation or lack of
availability of goods and services, environmental risks, drilling risks and
regulatory changes. Investors are cautioned that any such statements are not
guarantees of future performance and that actual results or developments may
differ materially from those projected in the forward-looking statements.

Investors and security holders are urged to read the proxy statement/prospectus
included in the Registration Statement on Form S-4 filed with the SEC in
connection with the proposed merger. PXP and 3TEC filed the proxy
statement/prospectus with the SEC on February 12, 2003. Investors and security
holders may obtain a free copy of the proxy statement/prospectus (when
available) and other documents filed by PXP and 3TEC with the SEC at the SEC's
web site at www.sec.gov. The proxy statement/prospectus and such other documents
(relating to PXP) may also be obtained for free from PXP by directing such
request to: Plains Exploration & Production Company, 500 Dallas, Suite 700
Houston, TX 77002, Attention: Joanna Pankey; telephone: (713) 739-6700; e-mail:
jpankey@plainsxp.com. The proxy statement/prospectus and such other documents
(relating to 3TEC) may also be obtained for free from 3TEC by directing such
request to: 3TEC Energy Corporation, 700 Milam, Suite 1100, Houston, Texas
77002, Attention: Investor Relations; telephone (713) 821-7100.

PXP, its directors, executive officers and certain members of management and
employees may be considered "participants in the solicitation" of proxies from
PXP's stockholders in connection with the merger. Information regarding such
persons and a description of their interests in the merger are contained in
the Registration Statement on Form S-4.

3TEC, its directors, executive officers and certain members of management and
employees may be considered "participants in the solicitation" in connection
with the merger. Information regarding such persons and a description of their
interests in the merger are contained in the Registration Statement on Form S-4.